Apparatus and Method for Positioning Extended Lateral Channel Well Stimulation Equipment

ABSTRACT

Disclosed is a movable boring assembly and a boring tool positioner for drilling a plurality of holes in a well casing and jetting a well production zone through the plurality of holes. All of the holes can be drilled in the casing at different angular positions, as well as different levels within the casing. The drilling tool can then be removed and a perforation jet can be reliably and accurately reoriented into the drilled holes to perforate a production zone in multiple directions and at multiple levels.

CROSS-REFERENCES TO RELATED APPLICATIONS

This is a continuation application of and claims priority to U.S. patentapplication Ser. No. 12/364,491 entitled “APPARATUS AND METHOD FORPOSITIONING EXTENDED LATERAL CHANNEL WELL STIMULATION EQUIPMENT” andfiled on Feb. 2, 2009 for Rudy Sanfelice et al., which is incorporatedherein by reference.

BACKGROUND OF THE INVENTION

Oil and gas well stimulation and mineral recovery equipment has beenused for radially hole boring through well casings into oil, gas, ormineral bearing geological formations.

Oil and gas wells are drilled into oil and/or gas bearing geologicalformations, and, when a combination of porosity and pressure gradient inthe formation are sufficient, the oil and/or gas in the formation flowsto the well bore, from which it either flows to the surface of theground under pressure or can be extracted by pumping. However, if eitherporosity of the formation or the pressure gradient is insufficient, flowrates of the oil and/or gas to the well bore may not enough for the wellto produce at its full potential and, in some cases, even to operate orproduce the well economically. This condition can be encountered in newwells and may develop over time in older wells.

To address these problems, many techniques have been developed forstimulating production from the formation, including, for example,treating the formation with acid, hydraulically fracturing the formationand propping the fractures open with porous propant materials andinjecting water or other fluids into the formation from nearby wells topush or induce increased flow of the oil and/or gas to the well bore.Such stimulation techniques can also be used in water wells as well asto make a formation less resistant to injection of fluids, such aswater, and to facilitate mineral recovery from mines, and otheroperations involving production from, and/or injection of fluids into,geological formations.

SUMMARY

The present invention may therefore comprise a movable boring assemblyfor drilling a plurality of holes in a well casing and jetting a wellproduction zone through the plurality of holes at a plurality of levelsand in a plurality of directions comprising: a boring tool positionerthat orients a drill tool to cut the plurality of holes in the pluralityof directions in the well casing and orient a perforation jet in theplurality of holes to perforate the well production zone in theplurality of directions; an antirotation mandrel coupled to a lower endof the boring tool positioner; a bow spring anchor that engages theantirotation mandrel to prevent the boring tool positioner fromrotating; a releasable packer that releasably couples to the wellcasing; a packer mandrel that rotates in the releasable packer to orientthe boring tool positioner in the plurality of directions to cut theplurality of holes in the well casing and to orient the perforation jetin the plurality of holes, and to vertically move the boring toolpositioner to more than one level in the well to bore holes andperforate production zones through the holes in the well casing at morethan one level.

The present invention may further comprise a boring tool positioner thatorients a drill tool to cut a plurality of holes in a plurality ofdirections in a well casing and reliably and accurately reorients aperforation jet in the plurality of holes to perforate a production zonethrough the plurality of holes in the well casing comprising: a housingsleeve having a plurality of apertures distributed around acircumferential wall on the housing sleeve; a tool guide cylinderpositioned rotatably in the housing sleeve that orients the drill tooland the perforation jet with the plurality of apertures; an angularpositioner that controls rotational movement of the tool guide cylinderin the housing sleeve in a manner that causes a releasable,self-latching engagement between the tool guide cylinder and the housingsleeve to accurately and repeatably align the tool guide cylinder withthe housing sleeve so that the drill tool and the perforation jet areaccurately and repeatably aligned with the plurality of apertures.

The present invention may further comprise a method of orienting a drilltool to cut a plurality of holes in a plurality of directions in a wellcasing of a well and reliably and accurately reorienting a perforationjet in the plurality of holes to perforate a production zone through theplurality of holes in the well casing comprising: providing a housingsleeve having a plurality of apertures distributed around acircumferential wall of the housing sleeve; holding the housing sleeveso that the housing sleeve does not rotate in the well; rotating a toolguide cylinder in the housing sleeve; aligning the tool guide cylinderin the housing sleeve so that the drill tool and the perforation jet areaccurately and repeatably aligned with the apertures.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are incorporated in and form a part ofthe specification, illustrate example implementations of the invention,which is defined by the claims, and they are not intended to imply thatthe claimed inventions are limited to these or any particular examplesor illustrations. In the drawings:

FIG. 1 is a side elevation view of an example boring tool positioningapparatus;

FIG. 2 is a cross-section view of the example boring tool positioningapparatus taken along the section line 2-2;

FIGS. 3 a-b are enlarged views of the upper and lower portions,respectively, of the example boring tool positioning apparatus in FIG.1;

FIGS. 4 a-b are enlarged cross-sectional views of the example boringtool positioning apparatus similar in orientation to FIG. 2;

FIG. 5 is an enlarged cross-section view of the top end of the boringtool positioning apparatus;

FIG. 6 is a side elevation view of the example boring tool positioningapparatus as first positioned in a well casing before it is anchored inposition;

FIG. 7 is a side elevation view of the upper portion of the exampleboring tool positioning apparatus in a well casing showing the anchorassembly before it is anchored in position;

FIG. 8 is a side elevation view similar to FIG. 7, but after the anchorassembly is set to anchor the example boring tool positioning apparatusin position in the well casing;

FIG. 9 is an enlarged cross-section view of the boring tool orientingassembly portion of the example boring tool positioning apparatus in asimilar orientation as FIG. 2;

FIG. 10 is a transverse cross-section view of the boring tool orientingassembly taken along section line 10-10 in FIG. 9;

FIG. 11 is a cross-section view similar to FIG. 9, but with the exampledrill tool in position for use;

FIG. 12 is a cross-section view similar to FIG. 11, but showing theexample drill tool position when the hole drilled through the wellcasing has been completed;

FIG. 13 is a cross-section view similar to FIG. 12, but with the drilltool removed from the boring tool orienting assembly and showing thecompleted hole drilled through the well casing;

FIG. 14 is a cross-section view similar to FIG. 13, but with the toolguide cylinder rotated about 45 degrees toward the next successive drillaperture;

FIG. 15 is a cross-section view similar to FIG. 13, but with the toolguide cylinder rotated about 90 degrees to the next successive drillaperture;

FIG. 16 is a transverse cross-section view of the boring tool orientingassembly of the example boring tool positioning apparatus in the wellcasing taken along section line 16-16 in FIG. 15;

FIG. 17 is an exploded, side elevation view of the pawl hub and end plugcomponents of an example angular positioning apparatus for the exampleboring tool positioning apparatus;

FIG. 18 is an exploded, longitudinal cross-section view of the pawl huband end plug components of the example angular positioning apparatusshown in FIG. 17;

FIG. 19 is a bottom plan view of the pawl hub of the example angularpositioning apparatus for the example boring tool positioning apparatus;

FIG. 20 is a top plan view of the end plug recesses for receiving thedogs of the pawl hub of the example angular positioning apparatus;

FIG. 21 is a top plan view of the socket that receives and secures thedrill tool in the boring tool orienting assembly;

FIG. 22 is a cross-section view of the socket taken substantially alonglines 22-22 in FIG. 21;

FIG. 23 is a cross-section view similar to FIG. 22, but showing thedrill tool nested in the socket;

FIG. 24 is a cross-section view of the boring tool orienting assemblysimilar to FIG. 11, but with the high pressure water jet boring toolbeing installed into the boring tool orienting assembly; and

FIG. 25 is a cross-section view of the boring tool orienting assemblysimilar to FIG. 24, but with the high pressure water jet boring toolpositioned in the boring tool orienting assembly and being used forboring a lateral channel into the reservoir formation.

FIG. 26 is a cross-sectional view of an embodiment of the boring toolorienting assembly.

FIG. 27 is a cross-sectional view of an embodiment of a drive shaftcoupling assembly.

FIGS. 28 through 31 illustrate an embodiment of a slip joint.

FIG. 32 illustrates an embodiment of a multi-level boring toolpositioner.

FIG. 33 is a top view of an embodiment of a spacer.

FIG. 34 is a side view of an embodiment of a movable boring tool.

FIG. 35 is a cross-sectional view of an embodiment of an anti-rotationmandrel.

FIG. 36 is a cross-sectional view of an embodiment of a bow springanchor.

FIG. 37 is a side view of the various elements of another embodiment ofa movable boring tool.

FIG. 38 is a cross-sectional view of an embodiment of a ball and detentlocking mechanism.

FIG. 39 is a cross-sectional view of an embodiment of a tapered pin andtapered aperture locking mechanism.

DETAILED DESCRIPTION OF EXAMPLE EMBODIMENTS

An example formation hole boring tool positioning apparatus 10 is showndiagrammatically in FIG. 1, but recognizing that the invention recitedin the claims below can also be implemented in myriad other ways, oncethe principles are understood from the description herein. Also, thisexample implementation is shown in a side elevation view of theassembled boring tool positioning apparatus 10 for the purpose ofgeneral orientation, but, because it is a fairly elongated apparatus, itmust be recognized that the scale as well as the two-dimensionalrepresentation has inherent limitations in showing details of theapparatus, some of which will be described or explained in more detailbelow and/or shown in subsequent views. A cross-sectional view of theexample radial hole boring tool positioning apparatus 10 taken along thesection line 2-2 in FIG. 1 is shown in FIG. 2 to supplement the initialgeneral orientation description. In the drawings and this description,“upwardly”, “downwardly”, “top”, “bottom”, “under”, “over”, and similardirectional prepositions are used for convenience to describecomponents, features, and functions of the positioning apparatus 10 asit would be positioned in a typical vertical well, which is as it isdepicted in the drawings, but recognizing that in some directionallydrilled wells, mining operations, and other applications, thelongitudinal axis 11 of the tool positioning apparatus 10 might beslanted to vertical or even horizontal. Therefore, in a generic sense,the prepositions relating generally to the upward direction are towardthe opening of the well or other bore hole at the surface of the ground,and those relating to the downward direction are away from the openingand into the formation.

The example hole boring tool positioning apparatus 10 shown in FIGS. 1and 2 is an elongated structure that has a diameter sized to fit andslide into a well casing, as will be described in more detail below,including an elongated carrier pipe 12 that serves as the primarystructural frame and carrier of the principal components of the boringtool positioning apparatus 10. An anchor assembly 14 positioned aroundthe carrier pipe 12 is provided for setting and anchoring the boringtool positioning apparatus 10 at a desired depth in the well (not shownin FIGS. 1 and 2), for example, in the pay zone of a reservoir formation(not shown in FIGS. 1 and 2). A boring tool orienting assembly 16 isattached to the bottom end 18 of the carrier pipe 12 for orienting thecasing drill tool 20 and formation jet boring tool (not shown in FIGS. 1and 2), as will be discussed in more detail below.

The casing drill tool 20 is shown in FIG. 2 for an overview of how thecomponents are generally assembled together, but, because of limitationsof scale and the two-dimensional drawing, are not entirely accurate inFIG. 2. For example, in use, the casing drill tool 20 would probably notbe lowered into the positioning apparatus 10 until the positioningapparatus 10 is already set and anchored in the well casing (not shownin FIG. 2), as will be discussed below. Also, the drill bit or cuttingtool 22 on the distal end of the flexible shaft 24 of the casing drilltool 20 is guided through the drill aperture 26 to cut or drill a hole(not shown in FIG. 2) through the casing (not shown in FIG. 2), so noneof the centralizer retainer apparatus of the orienting assembly 16, suchas the leaf spring 30, would not ordinarily be positioned in the sameangular position on the orienting assembly 16 as the drill aperture 26where it could block the drill bit 22 from reaching the casing (notshown in FIGS. 1 and 2).

The drill tool 20 is generally comprised of an elongated hydraulic motor40 (sometimes called a “mud motor” because it can be driven by theweighted circulating fluid in an oil well that is often called “mud”),which has a rotatable drive shaft 42 protruding axially at the bottomend. The flexible shaft 24 is connected to the drive shaft 42, so, whenthe hydraulic motor 40 turns the drive shaft 42, it turns the drill bit22 via the flexible shaft 24 to drill a hole through the casing (notshown in FIGS. 1 and 2.). A hydraulic fluid under pressure for drivingthe hydraulic motor 40 is delivered from a pump (not show) at thesurface of the ground (not shown) to the hydraulic motor 40 by ahigh-pressure tube or hose 44. Hydraulic motors or mud motors are wellknown in the oil and gas industry and readily available sizes andconfigurations that are suitable for the use described herein. Also,flexible shafts are well know and readily available. Any single ordouble ball-jointed or wire wound flexible shaft or other flexible shaftstructure that can fit in the tool described herein and transmit thepower from the hydraulic motor is suitable for this purpose.

A rotatable tool guide cylinder 46 with a curved guide channel 48 in theboring tool orienting assembly 16 is rotatable about the longitudinalaxis 11 of the positioning apparatus 10 for guiding the bit 22 andflexible shaft 24 to the appropriate drill apertures, e.g., apertures26, 28 (and others not seen in FIGS. 1 and 2), as will be explained inmore detail below. Angular positioning apparatus 50 in the boring toolorienting assembly 16 interacts with the rotatable tool guide cylinder46 for facilitating precision angular orientation of the rotatable guidecylinder 46 to align the distal end 52 of the guide channel 48 withselected ones of the drill apertures, e.g., drill aperture 26, 28 (andothers not seen in FIGS. 1 and 2), as will also be explained in moredetail below.

The example boring tool positioning apparatus 10 is shown in a largerscale in FIGS. 3 a-b and 4 a-b, wherein the upper portion is shown inFIGS. 3 a and 4 a and the lower portion is shown in FIGS. 3 b and 4 bwith some overlap of components between the upper FIGS. 3 a and 4 a andthe lower FIGS. 3 b and 4 b. The cross-section view in FIG. 4 a-billustrates the boring tool positioning apparatus 10 without the drilltool 20 in place, which is the way it would normally be run into thewell (not shown in FIGS. 3 a-b and 4 a-b), set, and anchored in place inthe well. Then, after the positioning apparatus 10 is set and anchoredin the well, as will be explained below, the drill tool 20 is droppedthrough the well and into the positioning apparatus 10, as will also beexplained below.

As best seen in the upper FIGS. 3 a and 4 a supplemented by FIG. 5(similar to the upper part of FIG. 4 a but enlarged and rotated 90degrees), the upper portion 54 of the carrier pipe 12 extends through awedge sleeve 56, lower spacer ring 58, axial thrust bearing 60, andupper spacer ring 62 into a pipe coupling 64. The pipe coupling 64 isinternally sized and threaded in its bottom portion 66 to receive andfasten to the externally threaded upper end 70 of the carrier pipe 12,and the upper portion 68 of the pipe coupling 64 is internally sized andthreaded to receive and fasten to an externally threaded lower end of anupset tubing string or production tubing string of a well (not shown inFIGS. 3 a, 4 a, and 5), which is used to lower the positioning apparatus10 into the well and to manipulate the anchor apparatus 14 and boringtool orienting assembly 16, as will be described in more detail below. Asplit ring 72 set into a corresponding annular groove 74 in the carrierpipe 12 provides a bottom limit to downward movement of the wedge sleeve56. Therefore, when the pipe coupling 64 is screwed onto the upper end70 of the carrier pipe 12, the upper spacer ring 58, thrust bearing 60,lower spacer ring 58, and wedge sleeve 56 are captured between thecoupling 64 and the spit ring 72 so that they cannot move longitudinallyupwardly and downwardly on the carrier pipe 12, but the carrier pipe 12is rotatable with respect to the wedge sleeve 56. Such rotatability ofthe carrier pipe 12 with respect to the wedge sleeve 56 allows thecarrier pipe 12 to be rotated by the upset/production tubing (not shownin FIGS. 3 a, 4 a, and 5) in order to manipulate the boring toolorienting assembly 16 while the wedge sleeve 56 is fixed immovably inthe well casing (not shown in FIGS. 3 a, 4 a, and 5) by the anchorassembly 14, which, when set, prevents the carrier pipe 12 from movinglongitudinally up and down in the well Likewise, the carrier pipe 12 isrotatable within the components of the anchor assembly 14, which will bedescribed in more detail below.

Referring again primarily to FIGS. 3 a and 4 a as well as to FIGS. 6-8,the anchor assembly 14 comprises two overlapping subassemblies—a wedgesubassembly 80 and a setting and releasing subassembly 82, whichinteract with each other to set and anchor the tool positioningapparatus 10 in the well casing 100 (FIGS. 6-8). The wedge subassemblyincludes a plurality of wedge pieces, for example, wedge pieces 84, 86,positioned slidably along the outside surface of the upper portion 54 ofthe carrier pipe 12 just under the wedge sleeve 56. The wedge pieces 84,86 are attached to the upper ends of two strap iron struts 88, 90,respectively, which are connected at their bottom ends to a cuff 92,which encircles and is slidably movable on the carrier pipe 12, and thecarrier pipe 12 is rotatable in the cuff 92. A plurality of leafsprings, for example, leaf springs 94, 96, extend downwardly from thecuff 92 and attach to a sleeve 98 positioned slidably around the carrierpipe 12 at a distance below the cuff 92. The leaf springs 94, 96 bowoutwardly between the cuff 92 and the sleeve 98 for engagement with thewell casing 100 when the tool positioning apparatus 10 is inserted intothe casing 100.

The setting and releasing subassembly 82 comprises a bayonet collar 102encircling the carrier pipe 12 in a slidable and rotatable manner forengaging and disengaging a bayonet pin 104 protruding radially from thecarrier pipe 12 below the sleeve 98 of the wedge subassembly 80. Aplurality of rigid bracket straps or bars, for example, bracket bars106, 108, extend upwardly from the bayonet collar 102 to a bracket band110 positioned slidably around the carrier pipe 12 above the sleeve 98of the wedge subassembly 80. The bracket bars 106, 108 are long enoughbetween the bracket band 110 and the bayonet collar 102 such that thesetting and releasing subassembly 82 has a range of motion upwardly anddownwardly on the carrier pipe 12 independent of the wedge subassembly80, but limited in the upward direction by the bayonet collar 102 cominginto abutment with the sleeve 98 and limited in the downward directionby the bracket band 110 coming into abutment with the sleeve 98. TheJ-slot 112 in the bayonet collar 102 allows the pin 104 to engage thecollar 102 for setting and releasing the wedge pieces 84, 86 to anchorand release the tool positioning apparatus 10 in the casing 100, as willbe described in more detail below, and it allows the disengagement ofthe collar 102 from the pin 104 for manipulating the boring toolorienting assembly 16 with the upset/production tubing via the carrierpipe 12 to set the angular orientation of the drilling tool 20 while thewedge subassembly 80 anchors the tool positioning apparatus 10 in thecasing 100, as will also be described below.

Referring now primarily to FIGS. 6-8, the boring tool positioningapparatus 10 is shown in FIG. 6, connected by the pipe coupling 64 tothe bottom end of an upset or production tubing string 114 and insertedinto a well casing 100. The surrounding formation is not shown in FIGS.6-8 to avoid unnecessary clutter. The leaf springs 94, 96 of the wedgesubassembly 80 and the leaf springs 30, 32, 34, 36 of the centralizerapparatus on the boring tool orienting assembly 16 are forciblydeflected by the casing 100 inwardly against their spring bias towardthe longitudinal axis 11 as the boring tool positioning apparatus 10 isforced by the upset/production tubing string 114 into the well, and theydrag against the inside surface of the casing 100 all the way down intothe well. Therefore, with particular attention to the anchor assembly14, the bayonet pin 104 protruding from the carrier pipe 12 and engagedin the I-slot 112 with the bayonet collar 102 applies a downward forceon the collar 102, bracket bars 106, 108, and bracket band 110 of thesetting and releasing subassembly 82. Consequently, the setting andreleasing subassembly 82 slides downwardly on the carrier pipe 12 untilthe bracket band 110 abuts the sleeve 98 of the wedge subassembly 80,whereupon the downward force is transferred to the wedge subassembly 80to overcome the frictional drag of the leaf springs 94, 96 to pull thewedge subassembly 80 downwardly through the casing 100 along with therest of the tool positioning apparatus 10, as shown in FIGS. 6 and 7, tothe desired depth in the well.

Once the desired depth is reached, the operator on the surface of theground pulls up slightly on the upset/production tubing string 114,which pulls the carrier pipe 12 upwardly and thereby causes the pin 104protruding from the carrier pipe 12 to move upwardly in the J-slot 112enough to dislodge the pin 104 from the closed end of the J-slot 112. Ifnecessary, the upset/production tubing string 114 can be pulled upwardlyenough to cause the collar 102 to abut the sleeve 98, which is heldstationary by the friction of the leaf springs 94, 96, in order todislodge the pin 104 from the closed end of the J-slot 112, whereuponthe operator then rotates the upset/production tubing string 114counter-clockwise to thereby rotate the carrier pipe 12 enough to alignthe pin 104 with the open end of the J-slot 112, and then the operatorlowers the upset/production tubing string 114 and carrier pipe 12 toremove the pin 104 from the J-slot 112, as illustrated in FIG. 8. Asalso illustrated in FIG. 8, as the carrier pipe 12 is lowered with thepin 104 out of the J-slot 112 and the friction of the leaf springs 94,96 holding the wedge subassembly 80 stationary in the casing 80, thedownward movement of the carrier pipe 12 in relation to the stationarywedge subassembly 80 causes the wedge sleeve 56, which moveslongitudinally with the carrier pipe 12, to also move downwardly betweenthe wedge pieces 84, 86. Such downward movement of the wedge sleeve 56with the carrier pipe 12 causes the tapered conical surface of the wedgesleeve 56 to force the wedge pieces 84, 86, which are constrainedagainst downward movement by the struts 88, 90, radially outward tothereby jam or wedge them between the wedge sleeve 56 and the casing100. With the wedge pieces 84, 86 wedged between the wedge sleeve 56 andcasing 100, the wedge sleeve 56 will not move up or down in the casing100, and, since the carrier pipe 12 cannot move longitudinally inrelation to the wedge sleeve 56, such jamming of the wedge pieces 84, 86between the wedge sleeve 56 and the casing 100 effectively anchors thecarrier pipe 12 in that position in the well. However, with the wedgesleeve 56 and carrier pipe 12 anchored against longitudinal movement inthe casing 100, the carrier pipe 12 is still rotatable in relation tothe wedge sleeve 56, as facilitated by the thrust bearing 60, so thecarrier pipe 12 can be rotated by the operator by rotating theupset/production tubing string 114 to manipulate the boring toolorienting assembly 16, as will be described below.

Alter the reservoir boring operations, which will be described below,are completed, the operator can disengage the anchor assembly 14 bypulling upwardly on the upset/production tubing string 112, thus pullingthe carrier pipe 12 upwardly in relation to the wedge subassembly 80,which pulls the wedge sleeve 56 upwardly and away from the wedge pieces84, 86, thereby releasing the radially outward force components on thewedge pieces 84, 86 to disengage them from the casing 100. As theupset/production tubing string 111 continues to pull the carrier pipe 12upwardly, the wedge subassembly initially remains stationary in thecasing 100 due to the frictional engagement of the leaf springs 94, 96on the inside surface of the casing 100. However, with further upwardmovement of the carrier pipe 12, the pin 104 bearing on the collar 102pushes the setting and releasing subassembly 82 upwardly along with thecarrier pipe 12 until the collar 102 reaches and pushes upwardly on thesleeve 98, whereupon continued upward movement of the carrier pipe 12cause the upward force of the pin 104 and collar 102 on the sleeve 98 toovercome the frictional resistance of the leaf springs 94, 96 on thecasing 100 to push the wedge subassembly 80 along with the rest of thetool positioning apparatus 10 upwardly and out of the well.

Turning now to the boring tool orienting assembly 16, after the toolpositioning apparatus 10 is set and anchored in the casing 100 at adesired depth in a reservoir formation, as explained above, the drilltool 20 (FIG. 2) is connected to and suspended on the end of thehydraulic fluid tube or hose 44 and lowered from the surface of theground (not shown) through the upset/production tubing string 112 (FIGS.6-8) into the anchored tool positioning apparatus 10. As shown generallyin FIG. 2, the flexible shaft 24 of the drill tool 20 with the drillcutter or bit 22 connected to the distal end of the flexible shaft 24gets guided initially by a socket 1 16 on the top end of a rotatabletool guide cylinder 46 into a curved guide channel 48 in the guidecylinder 46.

Referring now primarily to FIGS. 9 and 10, the socket fitting 116 can befastened to the top of the tool guide cylinder 46, for example, by pipethreads 118. The guide cylinder 46 is positioned rotatably in a housingsleeve 120 and attached by pipe threads 122 to the bottom end 18 of thecarrier pipe 12. The housing sleeve 120 is attached to and suspendedfrom a shoulder sleeve 124 by pipe threads 126, and the shoulder sleeveis supported by a thrust bearing 128 that bears on the top end 130 ofthe tool guide cylinder 46. Therefore, the carrier pipe 12 and the guidecylinder 46 are rotatable with respect to the shoulder sleeve 124 andhousing sleeve 120 about the longitudinal axis 11. The housing sleeve120 also has a plurality of drill apertures, for example, drillapertures 26, 27, 28, 29 distributed around the circumference of thehousing sleeve 120 in a common plane that is perpendicular to thelongitudinal axis 11, so that rotation of the guide cylinder 46 withrespect to the housing sleeve 120 can align the distal end 52 of theguide channel 48 with any one of the drill apertures, e.g., drillapertures 26, 27, 28, 29.

In the cross-section view of FIG. 9, two of the drill apertures 26, 28,which are diametrically opposite each other, are visible, but more thanthese two drill apertures 26, 28 can be provided. For example, in thisexample implementation, there are four drill apertures 26, 27, 28, 29,as shown in FIG. 10, distributed at angular increments of 90 degrees.These drill apertures 26, 27, 28, 29 allow the drill bit 22 to pass fromthe guide channel 48, through the housing sleeve 120, and into contactwith the casing 100, as illustrated in FIG. 11 for drilling holesthrough the casing 100, as will be discussed in more detail below.

With continuing primary reference to FIG. 9 and secondary reference toFIGS. 14, 17, and 18, the tool orienting assembly 16 is also equippedwith angular positioning apparatus 50, as mentioned briefly above, whichinteracts with the rotatable tool guide cylinder 46 for facilitatingprecision angular orientation of the rotatable guide cylinder 46 toalign the distal end 52 of the guide channel 48 with any of the drillapertures, e.g., drill aperture 26, 28. In FIGS. 9 and 10, the distalend 52 of the guide channel 48 is shown aligned with the drill aperture26. In the example implementation of the angular positioning apparatus50 illustrated in FIG. 9, a ratchet mechanism with a plurality ofspaced-apart slanted ratchet teeth, for example, the teeth 135, 137(plus several more that cannot be seen in the cross-section view of FIG.9), protruding downwardly from the bottom end of the tool guide cylinder46, and mating pawl teeth, for example pawl teeth 134, 136, 138, 140(also visible in FIGS. 17 and 18), protruding upwardly from an axiallyslidable pawl hub 132 into the notches or spaces between the ratchetteeth 135, 137, et al. In their engaged position, as shown in FIGS. 9and 10, the distal end 52 of the guide channel 48 is aligned with one ofthe drill apertures 26, 27, 28, 29, for example, with the drill aperture26.

The pawl teeth 134, 136, 138, 140 have to be cammed under the ratchetteeth 135, 137 et al. and thereby become disengaged from the ratchetteeth 135, 137 et al. in order for the tool guide cylinder 46 to rotateabout the longitudinal axis 11 while the housing sleeve 120 remainsstationary, as will be described in more detail below. The leaf springs30, 32, 34, 36 best seen in FIGS. 3 b and 10 centralize the housingsleeve 120 in the casing 100, and the frictional engagement of the leafsprings 30, 32, 34, 36 with the inside surface of the casing 100, asbest seen in FIG. 10, resists rotational movement of the housing sleeve120 while the tool guide cylinder 46 is rotated to orient the guidechannel 48 in the desired direction for the bit 22 of the drill tool 30(FIG. 11), as will be explained in more detail below. The pawl hub 132is movable downwardly against the spring force of the coil spring 142 inorder to accommodate such disengagement of the pawl teeth 134, 136, 138,140 from the ratchet teeth 135, 137, et al.

The pawl hub 132 and pawl teeth 134, 136, 138, 140 are prevented fromrotating along with the tool guide cylinder 46 and ratchet teeth 135,137 et al. inside the housing sleeve 120 by a dog clutch arrangement,wherein a plurality of dogs, for example, dogs 144, 146, 148, 150,protruding downwardly in the axial direction into a plurality of matingrecesses 154, 156, 158, 160 in the bottom end plug 162, as best seen inFIG. 9 along with FIGS. 17 and 18. The end plug 162 is attached to thebottom end of the housing sleeve 120 by pipe threads 164, as best seenin FIG. 9, so it is not rotatable with respect to the housing sleeve120, but the tool guide cylinder 46 is rotatable about the longitudinalaxis 11 with respect to the end plug 162, inhibited only by theinterfacing ratchet teeth 135, 137, et al. and pawl teeth 134, 136, 138,140. The pawl hub 132 is mounted and held in place on the end plug 162by a bolt 166, which extends through the central, axial hole 168 in thepawl hub 132 and is screwed into a threaded hole 170 in the end plug162. These components in operation will be described in more detailbelow.

With continuing reference primarily to FIGS. 9 and 11, bushings 172 and174 in the guide cylinder 46 at the distal end 52 of the guide channel48 and in the housing sleeve 120 around the drill aperture 26,respectively, help to stabilize and guide the drill bit 22 as it cuts ahole through the casing 100. Similar bushings 176, 178, 180 areinstalled in the other drill apertures 27, 28, 29 in the housing sleeve120, as shown in FIG. 10. As also best seen in FIG. 10 along with FIG. 3b, the leaf springs 30, 32, 34, 36 distributed around the outside of thehousing sleeve 120 stabilize and hold the housing sleeve 120 in thecenter of the casing 100 during operation of the drill tool 20 (FIG. 11)to cut or drill holes through the casing 100. Shallow channels 194, 195,196, 197 (FIG. 10) can be recessed into the outer surface of the housingsleeve 120 to provide extra room for the leaf springs 30, 32, 34, 36 tobe constricted by the inside surface of the casing 100 as the boringtool positioning apparatus 10 is pushed into the casing 100.

Referring now primarily to FIG. 11, when the tool guide cylinder 46 isset with the distal end 52 of the guide channel 48 in alignment with thedrill aperture 26, as shown in FIGS. 9 and 10, the drill tool 20 islowered into the boring tool positioning apparatus 10 until the cuttingtip of the drill bit 22 extends through the guide channel 48 and drillaperture 26 far enough to contact the inside surface of the casing 100,as shown in FIG. 11. In the example implementation illustrated in FIG.11, the longitudinal axis of the drill bit 22 in that position againstthe inside surface of the casing 100, where it is poised to startcutting or drilling a hole through the casing 100, is substantiallyperpendicular to the longitudinal axis 11 of the boring tool positioningapparatus 10, although other orientations or angular relationships couldalso be used.

The example socket 116 and self-engaging nesting of the drill motor 20in the example socket 116 is illustrated in FIGS. 11 and 21-23. Thesocket 116 comprises cylindrical body 240 with a longitudinal bore 242extending through its longitudinal axis 11. A conically tapered entrance244 leads downwardly to a larger diameter nesting bore 246, whichextends downwardly to diametrically opposite spiral shoulders 248, 250that spiral downwardly to respective diametrically opposite slots 252,254. The arrows 256, 258 in FIG. 21 indicate the downward spiralingdirection of the shoulders 248, 250. The first slot 252 extendslongitudinally downward from the top, starting edge 260 of the shoulder250 and from the lower terminal edge 262 of the spiral shoulder 248toward the bottom of the body 240. The second slot 254 extendsdownwardly from the top, starting edge 264 of spiral shoulder 248 andfrom the lower terminal edge 266 of the spiral shoulder 250 toward thebottom of the body 240. Both of the vertical slots 252, 254 intersectand extend radially outward from the longitudinal bore 242. The spiralshoulders can optionally have a hollow cut profile, as visible, forexample in the profiles of the edges 262, 264 in FIG. 22 and alsooptionally can have serrated glide surfaces 268, 270. The hollow cutprofile and/or serrated surfaces decrease surface area of the contactwith the drill motor 20 to reduce friction and enhance self-nesting ofthe drill motor 20 in the socket 116, as will be described below. Whenthe socket 116 is installed on the top end of the tool guide cylinder46, for example, by the pipe threads 118, the central bore 242 of thesocket 116 aligns with the proximal end 51 of the guide channel 48.

Referring now primarily to FIG. 23, along with FIGS. 11 and 21-22, thedrill motor 20 has a diameter that can fit into the nesting bore 246 anda drive shaft 42 that extends axially from a transmission housing 272.The transmission housing 272 is smaller in diameter than the drill motorbody 40 and fits into the main bore 242. A pair of ears 274, 276 extendradially outward from the transmission housing and are sized to slipinto the slots 252, 254. When the drill motor 20 is initially set intothe socket 116, the cutter 22 and flexible shaft 24 lead the way throughthe main bore 242 and into the guide channel 48. When the bottom edgesof the ears 274, 276 hit the spiral shoulders 248, 250, gravity and theweight of the drill motor 20 cause them to glide down the spiralshoulders 248, 250 as indicated by arrows 256, 258 in FIG. 21 to therespective lower edges 262, 264, where they drop into the slots 252,254. The drill tool 20 will continue dropping downwardly until thecutter 22 hits the casing 100 (FIG. 11), as explained above, Then, asthe cutter 22 cuts a hole 186 through the casing 100, the transmissionhousing 272 and ears 274, 276 (FIG. 23) can continue to movelongitudinally downwardly in the socket 116, but the ears 274, 276 inthe slots 252, 254 prevent rotational movement of the transmissionhousing 272 in the socket 1 16, and the bore 242 holds the transmissionhousing 272 snugly (not tightly) in the socket 116 to prevent excessivewobbling and other movement during the cutting operation.

As mentioned above, the hollow cuts on the top surfaces of the spiralshoulders 248, 250 leave sharp inside edges 278, 280 (FIG. 22) on whichthe bottom edge of the ears bear as they glide down the spiral shoulders248, 250, which presents a very small surface contact area, thus reducedfriction. As a result, the ears 274, 276, bearing the weight of thedrill tool 20, glide easily and smoothly into the slots 252, 254 to setthe drill tool firmly and securely into the socket 116. As alsomentioned above, serrated grooves 268 can also reduce friction andenhance gliding of the ears 274, 276 down the spiral shoulders 248, 250in to the slots 252, 254.

Hydraulic fluid, for example, drilling mud, water, or other fluid, canthen be pumped down the well though the tube or hose 44 (FIG. 2) topower the hydraulic motor 40 to rotate the flexible shaft 24 and drillcutter or bit 22. The weight of the hydraulic motor 40 maintainspressure on the drill bit 22 while it cuts a hole through the casing100, and a key tab 182 at the bottom of the hydraulic motor 40 interactswith a spiral keyway 184 in the socket 116 to prevent the hydraulicmotor 40 from turning instead of the flexible shaft 48 and drill bit 22.As the drill bit 22 cuts and advances through the casing 100, the lowerend of the hydraulic motor 40, including the drive shaft 42, continuesto sink lower into the socket 116, as shown in FIG. 12. As the drill bit22 cuts a hole 186 through the casing 100, a collar 188 with a largerdiameter than the bit 22 advances to abut against the casing 100 aroundthe new hole 186 to stop any further advance of the bit 22 and flexibleshaft 48 into the reservoir formation 190.

After the hole 186 has been drilled through the casing 100, as shown inFIG. 12, the drill tool 20 is then pulled upwardly to pull the drill bit22 back out of the newly drilled hole 186 in the casing 100 and out ofthe drill aperture 26 so that the tool guide cylinder 46 can bere-oriented to re-align the distal end 52 of the guide channel 48 withanother drill aperture, for example, the next drill aperture 27, in thehousing sleeve 120 (FIG. 16), in order to set up for drilling anotherhole through the casing 100 in a different direction. While it is onlynecessary to pull the drill tool 20 upwardly enough to pull thehydraulic motor 40, flexible shaft 24, and drill bit 22 back out of thenew hole 168 and the drill aperture 26 in order to rotate the tool guidecylinder 46, in practice, it may be more practical to pull the drilltool 20 with its flexible shaft 24 and bit 22 all the way out of theboring tool orienting assembly 16, as shown in FIG. 13, and suspend ithigher in the carrier pipe 12 or in the upset/production tubing 112(FIGS. 1-8) during the time that the tool guide cylinder 46 is rotatedto a new orientation, as will be described below. The first newlydrilled hole 186 in the casing 100 and extending slightly into thecement 192 is shown in FIG. 13.

With the drill tool 20 pulled up at least enough to withdraw the drillbit 22 from the newly drilled hole 186 and first drill aperture 26, asshown in FIG. 13, the tool guide cylinder 46 can be rotated to a newtool orientation, for example, to align the distal end 52 of the guidechannel 48 with the next drill aperture 27 (FIG. 16), which, in theexample being described, is oriented at about a 90 degree angle from thefirst drill aperture 26. To do so, the operator can rotate theupset/production tubing string 112 (FIGS. 6-8) clockwise in order torotate the carrier pipe 12 and tool guide cylinder 46 clockwise, asillustrated, for example, in FIG. 14, which shows the tool guidecylinder 46 rotated through an angle of about 45 degrees from the firstdrill aperture 26. It is also helpful to look at FIG. 16 along with FIG.14 for this explanation. Note that, because of the angular orientationof the cross-section view in FIG. 14, the leaf springs 30, 32, 34, 46around the outside of the housing sleeve 120 are not visible in FIG. 14,but they can be viewed in FIGS. 10 and 16, where they are shownmaintaining the tool orienting assembly 16 in the center of the casing100 while they also create frictional engagement with the inside surfaceof the casing 100 to resist rotation of the housing sleeve 120 as thecarrier pipe 12 and tool orienting cylinder 46 are rotated to newpositions.

In FIG. 14, the tool guide cylinder 46 is shown rotated about 45 degreesfrom the initial position where the first hole 186 was drilled throughthe casing 100, which, in the example illustrated, is about one-half ofthe angular rotation required to re-align the distal end of the guidechannel 48 with the next drill aperture 27 in the housing sleeve 120.The angular positioning apparatus 50 at this angular position shows thecoil spring 142 depressed by the pawl hub 132 enough to allow theratchet teeth 135, 137, 139, 141 on the bottom of the tool guidecylinder 46 to slide over and past the adjacent pawl teeth 134, 136,138, 140 in order rotate the tool guide cylinder 46 to the neworientation. Of course, not all of the ratchet teeth 135, 137, 139, 141and not all of the pawl teeth 134, 136, 138, 140 can be seen in FIG. 14,because FIG. 14 is a cross-section that shows only half of thestructure. However, persons skilled in the art can understand theinformation provided by the representative ratchet teeth and pawl teeththat can be seen in FIG. 14.

When the carrier pipe 12 is rotated, for example, the 45 degreesclockwise illustrated in FIG. 14, the tool guide cylinder 46 also getsrotated simultaneously by the same amount, because the tool guidecylinder 46 is attached rigidly, for example by pipe threads 122, to thecarrier pipe 12. However, because the housing sleeve 120 is supported bythe shoulder sleeve 124 on the thrust bearing 128 (FIG. 14) andconstrained from rotation by the leaf springs 30, 32, 34, 36 (FIG. 16),the housing sleeve 120 remains stationary, while the carrier pipe 12 andtool guide cylinder 46 are rotated. Also, the carrier pipe 12 and toolguide cylinder 46 are constrained against upward movement by the weightof the upset/production tubing string 112 (FIGS. 6-8), Therefore, as thetool guide cylinder 46 is rotated, the slanted ratchet teeth 135, 137,139, 141 on the bottom of the tool guide cylinder 46 interact with theslanted pawl teeth 134, 136, 138, 140 on the pawl hub 132 to push thepawl teeth 134, 136, 138, 140 and pawl hub 132 downwardly against theforce of the coil spring 142 so that the ratchet teeth 135, 137, 139,141 can slide over the tops of the pawl teeth 134, 136, 138, 140. Therecesses 154, 156, 158, 160 in the end plug 162 are deep enough for thedogs 144, 146, 148, 150 on the bottom of the pawl hub 132 to movefarther downwardly into the recesses 154, 156, 158, 160 to therebyaccommodate the axially downward movement of pawl hub 132 that isnecessary for the ratchet teeth 135, 137, 139, 141 to slide over thetops of the pawl teeth 134, 136, 138, 140, as illustrated in FIG. 14.

As soon as the tool guide cylinder 46 is rotated enough for the ratchetteeth 135, 137, 139, 141 to clear the tops of the pawl teeth 134, 136,138, 140, the force of the spring 142 snaps the pawl hub 132 backupwardly to seat the pawl teeth 134, 136, 138, 140 in the notches orspaces between the ratchet teeth 135, 137, 139, 141 and vice versa. Theratchet teeth 135, 137, 139, 141 and pawl teeth 134, 136, 138, 140 aresized and positioned in such a manner that such snapping of the pawl hub132 upwardly to seat the pawl teeth 134, 136, 138, 140 in the notchesbetween the ratchet teeth 135, 137, 139, 141 and vice versa occurs whenthe distal end 52 of the guide channel 48 is rotated into alignment withthe next drill aperture 27 in the housing sleeve 120, as illustrated inFIGS. 15 and 16.

Once the tool guide cylinder 46 is set with its distal end 52 inalignment with the second drill aperture 27, then the drill tool 20 canbe lowered back into the tool guide cylinder 46 to drill a second hole(not shown) in the casing through the second drill aperture 27 in thesame manner as described above for drilling the first hole 186 throughthe first drill aperture 26. Then, the angular reorientation, realign,drill, remove, and rotate procedures as described above can be performedin sequence until all of the desired holes are drilled in the casing100, for example, through the drill apertures 28 and 29, too. Of course,the angular rotation between successive drill apertures can be somethingother than the 90 degrees described in the example above, as long as thenumber and sizes of ratchet teeth and pawl teeth are made to matchwhatever number and angular orientation of drill apertures are desired.For example, if six drill apertures are spaced at thirty degreesintervals around the housing sleeve 120, then six ratchet teeth and sixpawl teeth sized and spaced to allow just thirty degrees rotationbetween each successive set and re-set of the ratchet and pawl assemblywould be needed.

Once all of the desired holes are drilled through the casing 100, thedrill tool 20 can be pulled out of the well and replaced by a highpressure water jet boring tool 200 for boring the holes farther outwardfrom the casing 100 into the formation 190, as illustrated, for example,in FIGS. 19 and 20. The example water jet boring tool 200 is illustratedin FIG. 19 as it is being lowered from the ground surface through theupset/production tubing string (not shown in FIG. 19) and carrier pipe12 into the boring tool orienting assembly 16, just before seating inthe socket 1 16. Throughout these operations, e.g., drilling a pluralityof holes 186 et al. through the casing 100, removing the drill tool 20,and replacing it with the high pressure jet boring tool 200, the housingsleeve 120 has not changed its position with respect to the casing 100,because the vertical anchor provided for the carrier pipe 12 by thewedge subassembly 80 described above (FIGS. 6-8) has not been released,and the leaf springs 30, 32, 34, 36 (FIGS. 10 and 16) have not allowedrotational movement of the housing sleeve 46 with respect to the casing100. Consequently, the drill apertures 26, 27, 28, 29 in the housingsleeve 120 remain adjacent and in alignment with the respective holes186, et al., in the casing 100 that were drilled through those drillapertures 26, 27, 28, 29, as described above. Therefore, the highpressure nozzle 202 of the high pressure water jet boring tool 200 canaccess the formation 190 through the same drill apertures 26, 27, 28, 29and the respectively drilled holes 168, et al., in the casing 100 viathe boring tool orienting assembly 16 by sequentially rotating the toolguide cylinder 46 to align the distal end 52 of the guide channel 48sequentially with each of the drill apertures 26, 27, 28, 29. Also,because the dogs 144, 146, 148, 150 of the pawl hub 132 positioned inthe recessed cavities 154, 156, 158, 160 prevent rotation of the pawlhub 132 with respect to the housing sleeve 120, thus also with respectto the drill apertures 26, 27, 28, 29, the angular positioning apparatus50 described above also enables the operator to use the tool guidecylinder 46 to re-access and direct the blasting nozzle 202 of the highpressure water jet boring tool 200 through the drill apertures 26, 27,28, 29 into the reservoir formation 190 in the same manner as describedabove for the drill tool 20.

Other angular positioning apparatus may also be used in the boring toolorienting assembly 16 instead of the ratchet and paw apparatus discussedabove. For example, one or more spring-loaded steel ball(s) (not shown)positioned between the bottom end of the tool guide cylinder 46 and theend plug 162 and associated detent holes (not shown) positioned ineither the bottom of the tool guide cylinder 46 or the top of the endplug 162 and positioned angularly to align the distal end 52 of theguide channel 48 with the respective drill apertures 26, 27, 28, 29 whenthe ball(s) are seated in the detent(s) could also be used.

The example water jet boring tool 200 shown in FIGS. 19 and 20 comprisesthe high pressure nozzle 202, sometimes called a jet nozzle or blasternozzle mounted on the end of a high pressure hose or tube 204, forexample, a metallic tube used in conventional coil tubing units used inthe oil and gas industry to direct a high pressure jet or blast of wateror other liquid or gas, such as air or nitrogen, into wells for clearingoperations or into rock or other formation material in oil wells. Theterms high pressure jet or blaster are common terms that refer to highpressure ejection of fluids, i.e., liquids or gases, for variouscutting, cleaning, or other purposes, where pressures in the range ofseveral thousand to over ten thousand pounds per square inch (psi) areinvolved. Therefore, for convenience, the general term “blaster tube” isused herein for the conduit 204, which is not intended to exclude highpressure hose or other materials that can be used in the apparatus andmethod described herein, but it does provide a convenient terminology toavoid confusion with the upset/production tubing string 112, which ismentioned above and may also be included in explanations or descriptionsrelating to oil and gas well applications for the described apparatusand methods.

An optional traveling block 210 can be used to house and protect thenozzle 202 during descent of the nozzle 202 into the well, and, theadded weight of the traveling block 210 on the distal end of the blastertube 204 can help to lead and guide the tube 204 and nozzle 202 down theupset/production tubing string 112 (not shown in FIG. 19) to the boringtool positioning apparatus 10. Therefore, the traveling block 210 cancomprise an elongated, heavy metal body with a longitudinal hole 210through its length with a diameter large enough for the blaster tube 204to pass or slide through unimpeded. A retainer ring 206 or other devicewith a diameter or other transverse dimension larger than the diameterof the hole 212 can be included, if necessary, in the nozzle 202components or otherwise provided at or near the distal end of theblaster tube 212 to retain the traveling block 210 on the blaster tube204 as it is lowered into the upset/production tubing string 112 or asit is pulled out of the upset/production tubing string 112. Of course,such a retainer ring 206 may not be necessary is the nozzle 202 itselfor fittings that fasten the nozzle 202 to the blaster hose 204 are largeenough to prevent the traveling block 210 from slipping off the blasterhose 204. However, the nozzle 202 has to be small enough in diameter topass unimpeded through the holes 186 that were drilled through thecasing 100 as described above in order to move through the holes 186into the formation 190. A nesting cavity 214 can be recessed into thedistal end 216 of the traveling block 210 with a diameter large enoughto receive the nozzle 202 (and retainer ring 206 if included) forprotection of the nozzle 202 on its descent through the upset/productiontubing string 112 (not shown in FIG. 19) to the boring tool positioningapparatus 10.

The traveling block 210 with the nozzle 202 nestled in the nestingcavity 214 is shown in FIG. 19 just as it is has been lowered from theupset/production tubing string 112 (shown in FIGS. 6-8, but not visiblein FIG. 19) into the carrier pipe 12 of the boring tool positioningapparatus 10 and is approaching the socket 116 of the boring toolorienting assembly 16 of the boring tool positioning apparatus 10. Asalso illustrated in FIG. 19, the tool guide cylinder 46 is rotated intoa position where the distal end 52 of the guide channel 48 is alignedwith a hole 186 that has been drilled through the casing 100 asdescribed above. While it can be aligned with any of the holes 186drilled through the casing 100, as a practical matter, it will probablybe the last hole 186 drilled through the casing 100 before the drilltool 20 was removed, because the tool guide cylinder 46 will most likelystill be set in that position when the blaster tube 204 and nozzle 202are first lowered into the boring tool positioning apparatus 10.

Upon reaching the boring tool orienting assembly 16, the blasting tube204 is lowered so that the distal end 216 of the traveling block 210reaches and sits or nests on the socket 116, where it stays. However, asalso shown in FIG. 20, the blaster tube 204 and nozzle 202 continue tobe lowered and/or pushed through the socket 116 and guide channel 48 ofthe tool guide cylinder 46 and through the drill aperture 26 and hole186 in the casing 100 to the cement 192 and/or reservoir formation 190.High pressure fluid, for example, water at a pressure in the range of2,000 to 12,000 psi or more is then delivered through the blaster tube204 and jetted through the nozzle 202 into the reservoir formation 190to jet bore a lateral channel 220 extending generally radially outwardfrom the casing 100. The length of the lateral channel 220 is optional,but it can be bored to extend hundreds of feet, if desired, from thecasing 100 into the reservoir formation 190.

When the desired lateral channel 220 has been bored, the blaster tube204 and nozzle 202 is pulled back out of the lateral channel 220 and outof the tool guide cylinder 46 so that the tool guide cylinder 46 can berotated, as described above, to re-align the distal end 52 of the guidechannel 48 with another drill aperture 26, 27, 28, or 29 andcorresponding hole 186 that has been drilled through the casing asdescribed above. When the guide channel 48 is so re-aligned to anotherhole 186 through the casing 100, the blaster tube 204 and nozzle 202 arethen re-inserted through the guide channel 48 and aligned drill aperture26, 27, 28, or 29 and hole 186 to the formation 190, and another lateralchannel 220 is jet blasted with the nozzle 202 into the formation 190.This process is repeated for any or all of the holes 186 that weredrilled through the casing 100, and, when completed, the blaster tube204 is pulled out of the boring tool positioning apparatus 10 and backto the surface. Then, the boring tool positioning apparatus 10 can bereleased from its anchored position in the casing 100, as describedabove, and pulled out of the well.

Another example of an angular positioning apparatus 50′ is illustratedin FIG. 26. In this example, a plurality of hard balls 300, e.g.,stainless steel, which are captured and spring-loaded by compressionsprings 304 in cylindrical container holes 306 in the bottom of the toolguide cylinder 46, interact with detent holes 302 in the top surface ofa platform 290 attached to the plug 162. As explained above, the plug162 is screwed into the bottom end of the housing sleeve 120, which isheld immovable in relation to the well casing 100 by a plurality of leafsprings 30, 32, 34, 36 (not seen in FIG. 26 because of the vieworientation), so the plug 162 and the platform 190, which is screwedtightly to the plug 162 by bolts 296, is also immovable with respect tothe housing sleeve 120 and well casing 100.

Therefore, when the tool guide cylinder 46 is rotated by the carrierpipe 12 to reorient the guide channel 48 to align with a different drillaperture, for example, from drill aperture 26 to the next drill aperture27 (not seen in FIG. 26), the balls 300 are forced against the force ofsprings 304 upwardly and out of the detent holes 302. As the tool guidecylinder 46 continues to rotate, balls 300, captured by the cylindricalholes 306, roll over the top surface 293 of the top flange 292 of theplatform 290 until they reach the next adjacent detent hole 302. Uponreaching the next adjacent detent holt 302, which occurs concurrentlywith the guide channel 48 coming into alignment with the next drillaperture, the balls 300, under the force of the springs 304, drop intothe respective detent holes 300 in a snap-like action, which can be feltor detected through the drill pipe at the surface of the well andimmediately provides a resistance to further rotation of the tool guidecylinder 46. Therefore, the operator at the well surface stops therotation and the balls 300 and detent holes 302 self-align the guidechannel 48 with the drill apertures both for boring holes through thecasing and then again for insertion of the blaster nozzle 202 and tube204 (not shown in FIG. 26) into the formation as described above. Acentering pin 298 can be provided on the bottom of the platform 290 forinsertion into a centering hole 299 in the plug 162 to assure alignmentof the detent holes 302 with the balls 300 before the bolts 296 aretightened onto the bottom flange 294 of the platform 290.

An example drive shaft coupling assembly 310 is shown in FIG. 27 forcoupling the flexible shaft 24 to the drive shaft 312 of the motor 40. Acoupling shaft 314 is connected to the motor drive shaft 312 by aflexible joint 316 comprising a socket 318 with a bore 320, whichreceives the top end 322 of the coupling shaft 314, a pin 324 thatextends through respective transverse holes in the socket 318 andcoupling shaft 314 to transmit rotational movement of the motor driveshaft 312 to the coupling shaft 314, and a threaded boss 326 forfastening the joint 316 to the distal end of the motor drive shaft 312.The fit of the coupling shaft 314 on the pin 324 is preferably but notnecessarily slidable, and in the fit of the coupling shaft 314 in thesocket hole 320 is preferably, but not necessarily, slightly loose, toaccommodate without transmitting some amount of wobble between the motordrive shaft 312 and the flexible shaft 24. Two sets of axial rotationbearings 330, 332 and thrust bearings 334, 336 bearing againstrespective annular shoulders 338, 340 of a bearing housing 272 andbearing on respective collars 344, 346 on the coupling shaft 314maintain lateral stability of the coupling shaft 314 and isolate themotor drive shaft 312 from longitudinal loads transmitted between thedrill tool 20 and the flexible shaft 24. Washers 348, 350 interfacebetween respective rotational bearings 330, 332 and thrust bearings 334,336. The bearing housing 272 is comprised of separate tubular sections352, 354 threaded for screwing together to accommodate assemblage overthe coupling shaft 314 and bearings as described above, and they arethreaded for attachment respectively to the motor 40 on top and to thenose piece 342 on the bottom, The bottom or distal end 356 of thecoupling shaft 314 is threaded for connection to the flexible shaft 24,and a lock nut 358 can be used to tighten the flexible shaft 24 to thecoupling shaft 314 after adjustment in the threads to place the drillbit 22 (not seen in FIG. 27) at the proper position for effective boringthrough the wall casing 100 as explained above.

A slip joint 360, as shown for example in FIGS. 28-31, can be placedbetween the carrier pipe 12 and the well upset/production tubing 114 inorder to accommodate elongation or shrinkage of the upset/productiontubing string in the well due to temperature changes and other forceswithout forcing the boring tool positioning apparatus out of itsanchored and set position in the casing during boring through the casing100 and into the reservoir 290. The example slip joint 360 shown in FIG.28 has a top sleeve 362 and an essentially identical bottom sleeve 364in which a coupling tube 366 can slide longitudinally, although one suchsleeve could be used. The top sleeve 362 is threaded and attached byscrewing to the bottom of the upset/production tube 114, and the bottomsleeve 364 can be attached to the coupling 64 (not shown in FIG. 28) orto a tubing length or adapter 368, which can be screwed into thecoupling 64, as will be understood by persons skilled in the art.

The coupling tube 366 has a flange 370 at its upper end and a similarflange 372 at its lower end, which fit slidably in the interiors of theupper and lower sleeves 370, 372, respectively, as shown in FIGS. 28 and29. An annular shoulder 374 at the distal end 376 of the top sleeve 362extends radially inwardly toward the coupling tube 366 to block theflange 370 from sliding out of the sleeve 362, but the flange 370 canslide up and down in the sleeve 362.

The coupling tube 366 is prohibited from rotating with respect to thesleeve 362 or vice versa by one or more splines 380 extending radiallyoutward from the coupling tube 366, which slide longitudinally throughmating slots 382 in the annular shoulder 374, while the annular shoulder374 interfaces with the splines to prevent rotation. The bottom sleeve364 also has a shoulder 378 that prevents the flange 372 at the bottomend of the coupling tube 366 from sliding out of the bottom sleeve 364,and it has similar slots 384 for allowing the splines 380 to slide intoand out of the sleeve 364, while the shoulder 378 interfaces the splines380 to prevent relative rotation between the coupling tube 380 and thelower sleeve 364.

FIG. 32 discloses a multi-level boring tool positioner 400. Themulti-level boring tool positioner 400 comprises a seating nipple 404that is attached to the tubing string 402. The seating nipple has arestricted inner diameter which provides a stop for the swab cups thatare used to swab the tubing. The seating nipple 404 is connected to thepacker mandrel 406. The packer mandrel comprises a standard mandrel thatis similar to the mandrel that is supplied with the packer 408, whichcan be moved in a vertical direction through the packer 408 and rotatedwithin the packer 408 to both set and release the packer 408. The packer408 may comprise a Baker model R3 double grip retrievable casing packer,product no. 642-01, that is available from Baker Oil Tools, a divisionof Baker Hughes, 9100 Emmott Road, Houston, Tex. 77040-3596. The packer408 is a setdown-type packer. The packer 408 is set by pulling up on thetubing string 402 until a release collar 411, that is connected to thebottom of the packer mandrel 406, engages the bottom of the packer. Thetubing string 402 can then be rotated in a clockwise direction to closeand seal the bypass valve when the release collar is allowed todisengage from the rocker slips 409. The setdown weight closes and sealsthe bypass valves, sets the slips and packs off the packing elements407. To release the packer, the tubing string 402 can be raised so thatthe packer mandrel 406 slides through the packer 408 and causes therelease collar to engage the bottom of the packer 408 and release slips409. The bypass valve opens to permit circulation through and around thepacker. The release collar 411 is shown in the upward released positionin FIG. 32.

As also shown in FIG. 32, the release collar 411 is connected to theperforated swabbing sub 410. The perforated swabbing sub 410 has aplurality of holes that allow fluid between the casing (not shown inFIG. 32) and the perforated swabbing sub 410 to penetrate the openingsand be swabbed from the interior of the tubing string 402. Asillustrated in FIG. 32, the release collar 411 is in the upward releaseposition so that the slips 409 and the packing elements 407 are notlocked onto the casing of the well. In the operating position, therelease collar is extended downwardly, and the packer mandrel 406extends through the packer 408. Hence, in the operating position, therelease collar 411 is separated by a distance from the slips 409 of thepacker mandrel 406. Once the packer 408 is set, fluids from the bottomof the well cannot pass between the packer and the well casing.

As further shown in FIG. 32, tubing spacer 412 provides a verticalspacing between the packer 408 and the boring tool positioner 414. Downhole well loggers, such as gamma ray well loggers, can identify thelocation of a production zones of interest in the well. The packer 408is located in the well so that the boring tool positioner 414 ispositioned directly in the production zone of the well, as indicated bythe well logger. The setdown procedure for setting the packer 408 maycause the boring tool positioner 414 to move downwardly by as much asapproximately two feet. Hence, the packer 408 must be positionedproperly to account for the setdown distance for setting the packer 408.The tubing spacer 412 allows the packer 408 to be positioned in a higherposition in the well, so that the packer 408 can engage a clean,unperforated portion of the casing to set the packer 408. There havebeen instances when packers have been set in areas where the casing hasbeen perforated, or has other problems, and the packer could not bereleased. Hence, the tubing spacer 412 provides spacing to allow thepacker 408 to be secured in the hole in an area where the casing willallow the packer 408 to be cleanly secured to the casing so that thepacker 408 can be easily released. The boring tool positioner 414corresponds to any one of the various embodiments disclosed herein, suchas the boring tool orienting assembly 16 disclosed above. Attached tothe bottom of the boring tool positioner 414 is a bow spring anchor 416.The bow spring anchor 416 anchors and centers the boring tool positioner414 in the casing.

In operation, the multi-level boring tool positioner 400, illustrated inFIG. 32, operates by pushing the entire assembly in the hole so that theboring tool positioner 414 is located in a lower portion of theproduction zone of the well when the packer mandrel 406 is extendeddownwardly through the packer 408. The packer mandrel 406 can be madeany desired length, so that it can be extended downwardly through thepacker 408, which allows the boring tool positioner 414 to be raised todifferent levels without moving or accidentally releasing the packer408. Accordingly, after the packer 408 is set, the setdown weight causesthe packer 408 to attach to the casing walls and the packer mandrel 406is extended downwardly through the packer 408 until the boring toolpositioner 414 reaches the first or lowest boring position in theproduction zone of the well. As described above, a drilling tool 20(FIG. 2) is used to bore four holes in the casing, so that a perforationjet, such as jet 200, can perforate the production zone in the well.Thereafter, the tubing string 402 is lifted by a predetermined amount,which causes the packer mandrel 406 to slide through the packer 408without disturbing the location of the packer 408. In that regard, thepacker mandrel 406 has a sufficient length that the release collar 411does not engage the slips 409, so that the packer 408 is not releasedfrom the casing. For example, the tubing string 402 may be lifted by twofeet, which causes the boring tool positioner 414 to move upwardly inthe hole by two feet. This also drags the bow spring anchor 416 upwardlyby two feet. On top of the well, a spacer is inserted by the operatorsthat fits around the tubing string between the lower surface of theelevators and the upper surface of the hydraulic slips that hold thetubing string. The spacer is placed around the tubing string between theupper surface of the hydraulic slips and the lower surface of theelevators and the elevators are lowered until the lower surface of theelevators rests on the spacer, which provides a predetermined spacebetween the lower surface of the elevators and the top surface of thehydraulic slips. In that manner, the boring tool positioner is raised bya predetermined amount, which can be repeatably and reliably obtainedusing the same spacer.

FIG. 33 discloses one implementation of a spacer 420. The spacer 420 hasan inside diameter that is greater than the tubing string and has anopening that allows the spacer 420 to be placed around the tubingstring, such as tubing string 402. For ease in handling, the spacerincludes a handle 422 for placing and removing the spacer 420 around thetubing string 402 between the top surface of the hydraulic slips and thelower surface of the elevators. The spacer 420 has a predeterminedlength, such as, for example, two feet. When the elevators are lowered,the spacer 420 provides a predetermined space, such as two feet, betweenthe bottom surface of the elevators and the upper surface of thehydraulic slips. In that manner, the boring tool positioner 414 is movedby two feet from its original level. New holes are then drilled in thecasing at the two foot higher level. This process can be repeatedseveral times, depending on the length of the packer mandrel 406.Different length spacers can be used to provide known spacings betweenthe bored holes. The packer mandrel 406, however, must be sufficientlylong, so that the release collar 416 does not engage the lower portionof the packer 408 to release the slips 409 and release the packer 408.Once multiple holes are drilled in the casing at the various levels, thedrill tool can be removed and a perforation jet can be lowered into theboring tool positioner 414. The holes in the casing can then accessopenings for the perforation jet to perforate the production zone of thewell. Then, the elevators can then be lifted and a new spacer placedbetween the lower surface of the elevators and the upper surface of thehydraulic slips, so that the boring tool positioner 414 accesses thenext level of holes. The perforation jet can then V blast perforationsat the next level. This process can be repeated for all levels at whichholes were drills in the casing. At each level, during both the boringand perforating procedures, the boring tool positioner 414 is rotated sothat holes and perforations can be made in a plurality of directions. Asthe tubing string 402 is lowered, the boring tool positioner 414 islowered and the bow spring anchor 416 is also moved in the casing.Typically, the bow spring anchor 416 will not rotate but move verticallyin the casing, both upwardly and downwardly. However, rotational flexionof the string, when the string is pushed or pulled, may cause the bowspring to rotate slightly. To ensure that there is no rotation, anotherembodiment is disclosed in FIGS. 34-37 of a movable boring tool 424.

FIG. 34 discloses a movable boring tool 424 that allows the bow springanchor 430 to be positioned within the well and not move and not allowthe boring tool positioner 426, illustrated in FIG. 34, to rotate as thetubing string moves upwardly and downwardly. The embodiments of FIGS. 34through 37 uses an anti-rotation mandrel 428 that slides through the bowspring anchor 430 so that the bow spring anchor 430 does not move whenthe tubing string, and hence the boring tool positioner 426, is movedupwardly and downwardly to different positions in the production zone.As shown in FIG. 35, the anti-rotation mandrel 428 may have a shape,such as a hexagonal shape, which fits into the hexagonal shape of thebow spring anchor 430 that is illustrated in FIG. 36. In this manner,the anti-rotation mandrel 428 can slide easily within the interior ofthe bow spring anchor 430, but be held in a position so that the boringtool positioner 426 does not rotate as a result of the bow spring anchor430 holding the anti-rotation mandrel 428 in a predeterminedorientation. Mandrel stop 431 engages the bottom of the bow springanchor 430 to allow extraction of the bow spring anchor. The boring toolpositioner 426 engages the bow spring anchor 430 and drives it downthrough the hole until the boring tool positioner 426 is located at thelowest level at which perforations in the production zone are going tobe made. The boring tool positioner 426 is then sequentially raisedmultiple times, using the process described above, which employs aspacer, such as spacer 420, to repeatably access the multiple levels atwhich holes are drilled in the casing. Since the bow spring anchor 430remains anchored and does not move, the chances of rotation of theboring tool positioner 426, during the process of raising and loweringthe boring tool positioner 426, is virtually eliminated. In this manner,alignment of the holes in the casing is highly accurate when the jettingdevice is lowered into the boring tool positioner 426. Although theanti-rotation mandrel 428 and the bow spring anchor 430 are shown ashaving hexagonal shapes to prevent rotation, any desired shape can beused, as well as key slots with key pins and other shapes, to preventrotation.

FIG. 37 discloses additional components of the embodiment that isillustrated in FIG. 34. As shown in FIG. 37, the tubing 432 that extendsup the hole is attached to a seating nipple 434. The seating nipple 434prevents the swab cups that are inserted into the tubing 432 to swab thetubing from passing below the seating nipple 434. The packer mandrel 436extends through the packer 438 and includes a release collar 440 that isattached to the bottom of the packer mandrel 436. Packer 438 can be aretrievable R-type of packer mandrel, such as those that are availablefrom Baker Oil Tools, a division of Baker Hughes, 9100 Emmott Road,Houston, Tex. 77040-3596. As disclosed above, the packer mandrel 436must be longer than the distance in which perforations are to be made inthe production zone to prevent the release collar 440 from releasing thepacker mandrel 436 when the packer mandrel 436 is sequentially raisedand spacers are placed around the tubing 432 at the surface of the well.The packer mandrel 436 comprises the standard packer mandrel that isused with the packer 438, which is round and slides through and rotateswithin the packer 438. The entire string illustrated in FIG. 37 isdriven downwardly in the hole to set the bow spring anchor below thelowest level at which perforations will be made in the production zone.The string is then raised to raise the packer 438, so that the releasecollar 440 engages the packer 438 and the packer 438 is raised to theposition at which it will be anchored in the casing. The anti-rotationmandrel 428 is sufficiently long so that the bow spring anchor 430 isnot disturbed when the packer 438 is raised to a proper position foranchoring. The tubing 432 is then rotated, which rotates the packermandrel 436, to set the packer 438 against the casing. Packer mandrel436 is then lowered, so that the release collar 440 lowers, as well asthe remaining portion of the string, including the perforated swabbingsub 444, the tubing spacer 448, the boring tool positioner 426, and theanti-rotation mandrel 428, until the boring tool positioner 426 is inthe position at which a lower set of perforations will be made in theproduction zone.

As shown in FIG. 37, the release collar 440 is connected to theperforated swabbing sub 444 by the coupling collar 442. Since the packer438 may slightly move during the process of setting the packer 438, theanti-rotation mandrel 428 should be made several feet longer than thepacker mandrel 436. Tubing spacer 448 functions in the same manner asthe tubing spacer 412, illustrated in FIG. 32, which allows the packer438 to be placed in clean, unperforated casing higher in the hole.Rotation of the string does not occur below the boring tool positioner426. As indicated above, the string can be rotated in the boring toolpositioner 426 to access the various openings in the boring toolpositioner 426. This rotation of the string 432 and the packer mandrel436 does not affect the packer 438 once the packer mandrel 438 is set.The outer portion of the boring tool positioner 426 does not rotate withthe string, as disclosed above, but is tied directly to theanti-rotation mandrel 428. The bow spring anchor 430, as described abovewith respect to FIGS. 34-36, anchors the anti-rotation mandrel 428 andprevents the anti-rotation mandrel 428 from rotating in the hole, sothat the boring tool positioner 428 can be accurately located whenrepositioned to perform the jet blasting procedure. The mandrel stop 431allows the bow spring anchor 430 to be retrieved upon removal of thestring.

In operation, the embodiment of FIGS. 32-37 allows the boring toolpositioner 426 to drill holes and perforate a production zone atmultiple levels, restricted only by the length of the packer mandrel 436and the anti-rotation mandrel 428. The anti-rotation mandrel 428prevents the boring tool positioner 426 from rotating, since the bowspring anchor 430 is anchored within the casing and does not movevertically, and does not allow the boring tool positioner 426 to rotate.Hence, angular position of the boring tool positioner 426 is maintainedin a highly accurate manner. Further, the use of spacers, such as spacer420, illustrated in FIG. 33, allows the boring tool positioner 426 to bevery accurately located in a vertical direction, since the spacer ishard set between the upper surface of the hydraulic slips and the lowersurface of the elevators. Of course, any type of spacer can be used, aslong as it is capable of carrying the weight of the entire string. Inaddition, various shapes and other designs can be used, as long as thespacer provides a space between the lower portion of the elevators andthe upper surface of the hydraulic slips. Alternatively, the elevatorscan be moved a precise distance, which can be measured by the operator.In this manner, a repeatable depth may be achievable for the boring toolpositioner 426. The embodiment illustrated in FIG. 37 allows multiplelayers of holes to be drilled in the casing and these holes to beprecisely and repeatably located after the drilling tool is removed andthe perforation jet is placed in the boring tool positioner 426.Accurate location of the opening in the boring tool positioner 426 withthe hole that is bored in the casing prevents the jet blaster from beinglodged and stuck between the boring tool positioner 426 and the openingin the casing.

In the various embodiments disclosed herein, the tubing string 436 canbe rotated along with the packer mandrel 436, release collar 440,coupling collar 442, perforated swabbing sub 444 and tubing spacer 448,which rotates the internal portion of the boring tool positioner 426, byattaching a large wrench to the tubing 432 at the surface. An operatorcan rotate the tubing string in a first direction, using a large wrench,such as a 24 inch wrench, until the operator feels the snap of thespring 142 setting the boring tool positioner 426 on the incline planes.The operator then pulls the device in the opposite direction to ensurethat the boring tool positioner 426 is properly seated along the inclineplanes. Once the holes are drilled in the casing or the jetting is done,the operator then rotates the tubing string 402 again until the operatordetects another vibration caused by the spring when the boring toolpositioner 426 seats in the next position, The operator again reversesthe direction of rotation of the string to ensure that the inclineplanes are properly seated. The operator can then proceed with eitherthe drilling or the jetting process. This process is repeated for eachopening in the boring tool positioner 426, for example, four times ateach level. It has been empirically determined that the amount ofrotation of the wrench at the surface does not correspond with theamount of rotation of the string within the boring tool positioner 428.For example, a full 360° rotation of the boring tool positioner 426 mayonly result in approximately 180° or 190° of rotation on the surface.This may be due to the rotational flexion of the tubing 432 at longdistances, which, in some wells, may be over a mile between the surfaceand the boring tool positioner 426. Hence, the process of detecting thevibration created by the spring 142 (FIGS. 17 and 18) allows an accurateway of detecting the proper setting of the boring tool positioner 426 inthe various settings, such as the four settings illustrated in theembodiments disclosed above.

FIG. 38 is a cutaway view of a ball and detent arrangement for lockingthe tool guide cylinder 448 in place. The tool guide cylinder 448 hastwo detents 444, 446 that engage the balls 440, 442 on the angularpositioner 452, Balls 440, 442 are held within the detents 444, 446 bythe upward pressure of spring 450 on the angular positioner 452. In thismanner, the tool guide cylinder 448 can be releasably rotated andreleasably latched into place at each 90° position, or other angularposition, depending upon the location of the detents, to hold the toolguide cylinder 448 in alignment with the apertures on the housing sleeve454.

FIG. 39 is another embodiment of a device for releasably latching thetool guide cylinder. As shown in FIG. 39, tapered pins 456, 458 engagethe tapered apertures 460, 462. The angular positioner 464 is held inplace by the spring 466. This process locks the tool guide cylinder 466in predetermined positions so that the tool guide cylinder 466 can bealigned with the apertures in the housing sleeve 468.

The foregoing description of the invention has been presented forpurposes of illustration and description. It is not intended to beexhaustive or to limit the invention to the precise form disclosed, andother modifications and variations may be possible in light of the aboveteachings. The embodiment was chosen and described in order to bestexplain the principles of the invention and its practical application tothereby enable others skilled in the art to best utilize the inventionin various embodiments and various modifications as are suited to theparticular use contemplated. It is intended that the appended claims beconstrued to include other alternative embodiments of the inventionexcept insofar as limited by the prior art

1. A movable boring assembly for drilling a plurality of holes in a well casing and jetting a well production zone through said plurality of holes at a plurality of levels and in a plurality of directions comprising: a boring tool positioner that orients a drill tool to cut a plurality of holes in a plurality of directions in a well casing and orient a perforation jet in said plurality of holes to perforate a well production zone in said plurality of directions; an antirotation mandrel coupled to a lower end of said boring tool positioner; and a bow spring anchor that engages said antirotation mandrel to prevent said boring tool positioner from rotating.
 2. The movable boring assembly of claim 1, further comprising an anchor assembly that anchors said boring tool positioner at a predetermined level in said well.
 3. The movable boring assembly of claim 1 wherein said boring tool positioner comprises: a housing sleeve having a plurality of apertures distributed at different locations on said housing sleeve; a tool guide cylinder positioned rotatably in said housing sleeve that orients said drill tool and said perforation jet with said plurality of apertures; an angular positioner that controls rotational movement of said tool guide cylinder in said housing sleeve in a manner that causes a releasable, self-latching engagement between said tool guide cylinder and said housing sleeve to accurately and repeatably align said tool guide cylinder with said housing sleeve so that said drill tool and said perforation jet are accurately and repeatably aligned with said plurality of apertures.
 4. The movable boring assembly of claim 3 wherein said angular positioner comprises one or more of: a ratchet and paw; a spring-loaded ball and detent; and a retractable tapered pin and mating tapered aperture.
 5. The movable boring assembly of claim 3 wherein said tool guide cylinder has a curved channel that extends from a proximal end of said tool guide cylinder, and is substantially centered on a longitudinal axis of said tool guide cylinder, to a distal end and exists said tool guide cylinder at an angle of approximately 90° to said axis.
 6. The movable boring assembly of claim 5 further comprising: a socket disposed at said tool guide cylinder that receives and guides said drill tool and said perforation jet into and through said curved channel.
 7. The movable boring assembly of claim 6 wherein said socket further comprises a center bore that receives and retains a drill motor, longitudinal slots formed in said socket along said center bore, spiral shoulders formed on said proximal end of said socket in said center bore that engage radially extending ears from a transmission of said drill motor.
 8. The movable boring tool assembly of claim 7 further comprising: a support that connects said boring tool positioner to a tubing string that extends to the surface of said well.
 9. The movable boring tool assembly of claim 8 wherein said support comprises a carrier pipe.
 10. The movable boring tool assembly of claim 8 further comprising: a boring tool positioner bow spring anchor that is coupled to said housing sleeve that holds said housing to said well casing to prevent rotation and centers said boring tool positioner in said well casing.
 11. An apparatus comprising: a tool guide cylinder positioned rotatably in a housing sleeve that orients a drill tool and a perforation jet with a plurality of apertures distributed around a circumferential wall on said housing sleeve; an angular positioner that aligns said tool guide cylinder with said housing sleeve so that said drill tool and said perforation jet are aligned with said plurality of apertures.
 12. The boring tool positioner of claim 11 wherein said angular positioner comprises one or more of: a ratchet and paw; a spring-loaded ball and detent; and a retractable tapered pin and mating tapered aperture.
 13. The boring tool positioner of claim 11 wherein said tool guide cylinder has a curved channel that extends from a proximal end of said tool guide cylinder, and is substantially centered on a longitudinal axis of said tool guide cylinder, to a distal end and exists said tool guide cylinder at an angle of approximately 90° to said axis.
 14. The boring tool positioner of claim 13 further comprising: a socket disposed at said tool guide cylinder that receives and guides said drill tool and said perforation jet into and through said curved channel wherein said socket further comprises a center bore that receives and retains a drill motor, longitudinal slots formed in said socket along said center bore, spiral shoulders formed on said proximal end of said socket in said center bore that engages radially extending ears from a transmission of said drill motor.
 15. The boring tool positioner of claim 14 further comprising: a support that connects said boring tool positioner to a tubing string that extends to the surface of said well.
 16. The boring tool positioner of claim 15 further comprising: a boring tool positioner bow spring anchor that is coupled to said housing sleeve that holds said housing to said well casing to prevent rotation and centers said boring tool positioner in said well casing.
 17. A method comprising: providing a housing sleeve having a plurality of apertures distributed around a circumferential wall of said housing sleeve; holding said housing sleeve so that said housing sleeve does not rotate in a well; and aligning a tool guide cylinder in said housing sleeve so that a drill tool and a perforation jet are aligned with said apertures.
 18. The method of claim 17 wherein said process of holding said housing sleeve comprises: anchoring said housing sleeve to said well casing.
 19. The method of claim 18 wherein said process of holding said housing sleeve comprises: anchoring an antirotational mandrel to said well casing that allows said housing sleeve to be moved vertically in said well but prevents rotational movement of said housing sleeve.
 20. The method of claim 19 wherein said process of aligning said tool guide cylinder in said housing sleeve comprises: using an angular positioner that releasably sets an angular position of said tool guide cylinder in said housing sleeve using a self-latching mechanism. 